Engineering Papers⌕ Search

SEARCH · Engineering Papers

Results for “AMINES”

Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 1,135 records · Page 63
All sourcesNASA NTRSDOE OSTI
DOE OSTI2013

Hybrid Membrane/Absorption Process for Post-combustion CO2 Capture

This report summarizes scientific/technical progress made for bench-scale membrane contactor technology for post-combustion CO2 capture from DOE Contract No. DE-FE-0004787. Budget Period 1 (BP1) membrane absorber, Budget Period 2 (BP2) membrane desorber and Budget Period 3 (BP3) integrated system and field testing studies have been completed successfully and met or exceeded the technical targets (≥ 90% CO2 removal and CO2 purity of 97% in one membrane stage). Significant breakthroughs are summarized below: BP1 research: The feasibility of utilizing the poly (ether ether ketone), PEEK, based hollow fiber contractor (HFC) in combination with chemical solvents to separate and capture at least 90% of the CO2 from simulated flue gases has been successfully established. Excellent progress has been made as we have achieved the BP1 goal: ≥ 1,000 membrane intrinsic CO2 permeance, ≥ 90% CO2 removal in one stage, ≤ 2 psi gas side pressure drop, and ≥ 1 (sec)-1 mass transfer coefficient. Initial test results also show that the CO2 capture performance, using activated Methyl Diethanol Amine (aMDEA) solvent, was not affected by flue gas contaminants O2 (~3%), NO2 (66 ppmv), and SO2 (145 ppmv). BP2 research: The feasibility of utilizing the PEEK HFC for CO2-loaded solvent regeneration has been successfully established High CO2 stripping flux, one order of magnitude higher than CO2 absorption flux, have been achieved. Refined economic evaluation based on BP1 membrane absorber and BP2 membrane desorber laboratory test data indicate that the CO2 capture costs are 36% lower than DOE’s benchmark amine absorption technology. BP3 research: A bench-scale system utilizing a membrane absorber and desorber was integrated into a continuous CO2 capture process using contactors containing 10 to 20 ft2 of membrane area. The integrated process operation was stable through a 100-hour laboratory test, utilizing a simulated flue gas stream. Greater than 90% CO2 capture combined with 97% CO2 product purity was achieved throughout the test. Membrane contactor modules have been scaled from bench scale 2-inch diameter by 12-inch long (20 ft2 membrane surface area) modules to 4-inch diameter by 60-inch long pilot scale modules (165 ft2 membrane surface area). Pilot scale modules were tested in an integrated absorption/regeneration system for CO2 capture field tests at a coal-fired power plant (Midwest Generation’s Will County Station located in Romeoville, IL). Absorption and regeneration contactors were constructed utilizing high performance super-hydrophobic, nano-porous PEEK membranes with CO2 gas permeance of 2,000 GPU and a 1,000 GPU, respectively. Field tests using aMDEA solvent achieved greater than 90% CO2 removal in a single stage. The absorption mass transfer coefficient was 1.2 (sec)-1, exceeding the initial target of 1.0 (sec)-1. This mass transfer coefficient is over one order of magnitude greater than that of conventional gas/liquid contacting equipment. The economic evaluation based on field tests data indicates that the CO2 capture cost associated with membrane contactor technology is $54.69 (Yr 2011$)/tonne of CO2 captured when using aMDEA as a solvent. It is projected that the DOE’s 2025 cost goal of $40 (Yr 2011$)/tonne of CO2 captured can be met by decreasing membrane module cost and by utilizing advanced CO2 capture solvents. In the second stage of the field test, an advanced solvent, Hitachi’s H3-1 was utilized. The use of H3-1 solvent increased mass transfer coefficient by 17% as compared to aMDEA solvent. The high mass transfer coefficient of H3-1 solvent combined with much more favorable solvent regeneration requirements, indicate that the projected savings achievable with membrane contactor process can be further improved. H3-1 solvent will be used in the next pilot-scale development phase. The integrated absorption/regeneration process design and high performance membrane contactors developed in the current bench-scale program will be used as the base technology for future pilot-scale development.

Coal-Environmental Processes↗
DOE OSTI2014

Novel Non-Aqueous CO 2 Solvents and Capture Process with Substantially Reduced Energy Penalties (Final Scientific/Technical Report)

The overall objective of this 3 year project was to rapidly advance the development a family of promising NAS formulations from proof-of-concept testing through to testing in a representative process arrangement to determine the potential for this novel solvent-based process to substantially reduce (i.e., >40%) the energy demand and cost of CO 2 capture from fossil fuel-fired electricity generating units. The goal of this project was to thoroughly characterize the NASs and evaluate their performance in a small process unit to understand their potential to lower the energy demand of a CO 2 capture process and demonstrate feasibility. Detailed characterization of the thermodynamic properties of the NASs revealed large working capacities under low regeneration temperatures (i.e., <100°C) and lower heats of absorption than conventional aqueous amine solvents. The thermal energy demand for these promising NAS formulations was estimated to be approximately 40% less than conventional aqueous-amine solvents (2.06-2.15 GJt / tonne CO 2 vs 3.6 GJt / tonne CO 2 ).

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2016

Characterization of solids deposited on the modular caustic-side solvent extraction unit (MCU) coalescer media removed in October 2014

In February 2015, Savannah River National Laboratory (SRNL) received a Strip Effluent (SE) coalescer (FLT-304) from MCU. That coalescer was first installed at MCU in July 2014 and removed in October 2014. While processing approximately 31,400 gallons of strip solution, the pressure drop steadily increased from 1 psi to beyond the administrative limit of 20 psi. The physical and chemical analysis was conducted on this coalescer to determine the mechanism that led to the plugging of this coalescer. Characterization of this coalescer revealed the adsorption of organic containing amines as well as MCU modifier. The amines are probably from the decomposition of the suppressor (TiDG) as well as from bacteria. This adsorption may have changed the surface energetics (characteristics) of the coalescer fibers and therefore, their wetting behavior. A very small amount of inorganic solids were found to have deposited on this coalescer (possibly an artifact of cleaning the coalescer with Boric acid. However, we believe that inorganic precipitation, as has been seen in the past, did not play a role in the high pressure drop rise of this coalescer. With regards to the current practice of reducing the radioactive content of the SE coalescer, it is recommended that future SE coalescer should be flushed with 10 mM boric acid which is currently used at MCU. Plugging of the SE coalescer was most likely due to the formation and accumulation of a water-in-oil emulsion that reduced the overall porosity of the coalescer. There is also evidence that a bimodal oil particle distribution may have entered and deposited in the coalescer and caused the initial increase in pressure drop.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2016

Low Cost, High Capacity Regenerable Sorbent for Carbon Dioxide Capture from Existing Coal-fired Power Plants

In this project TDA Research, Inc (TDA) has developed a new post combustion carbon capture technology based on a vacuum swing adsorption system that uses a steam purge and demonstrated its technical feasibility and economic viability in laboratory-scale tests and tests in actual coal derived flue gas. TDA uses an advanced physical adsorbent to selectively remove CO 2 from the flue gas. The sorbent exhibits a much higher affinity for CO 2 than N 2 , H 2 O or O 2 , enabling effective CO 2 separation from the flue gas. We also carried out a detailed process design and analysis of the new system as part of both sub-critical and super-critical pulverized coal fired power plants. The new technology uses a low cost, high capacity adsorbent that selectively removes CO 2 in the presence of moisture at the flue gas temperature without a need for significant cooling of the flue gas or moisture removal. The sorbent is based on a TDA proprietary mesoporous carbon that consists of surface functionalized groups that remove CO 2 via physical adsorption. The high surface area and favorable porosity of the sorbent also provides a unique platform to introduce additional functionality, such as active groups to remove trace metals (e.g., Hg, As). In collaboration with the Advanced Power and Energy Program of the University of California, Irvine (UCI), TDA developed system simulation models using Aspen PlusTM simulation software to assess the economic viability of TDA’s VSA-based post-combustion carbon capture technology. The levelized cost of electricity including the TS&M costs for CO 2 is calculated as $116.71/MWh and $113.76/MWh for TDA system integrated with sub-critical and super-critical pulverized coal fired power plants; much lower than the $153.03/MWhand $147.44/MWh calculated for the corresponding amine based systems. The cost of CO 2 captured for TDA’s VSA based system is $38.90 and $39.71 per tonne compared to $65.46 and $66.56 per tonne for amine based system on 2011 $ basis, providing 40% lower cost of CO 2 captured. In this analysis we have used a sorbent life of 4 years. If a longer sorbent life can be maintained (which is not unreasonable for fixed bed commercial PSA systems), this would lower the cost of CO 2 captured by $0.05 per tonne (e.g., to $38.85 and $39.66 per tonne at 5 years sorbent replacement). These system analysis results suggest that TDA’s VSA-based post-combustion capture technology can substantially improve the power plant’s thermal performance while achieving near zero emissions, including greater than 90% carbon capture. The higher net plant efficiency and lower capital and operating costs results in a substantial reduction in the cost of carbon capture and cost of electricity for the power plant equipped with TDA’s technology.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2016

Evaluation of Solid Sorbents as a Retrofit Technology for CO 2 Capture

ADA completed a DOE-sponsored program titled Evaluation of Solid Sorbents as a Retrofit Technology for CO 2 Capture under program DE-FE0004343. During this program, sorbents were analyzed for use in a post-combustion CO 2 capture process. A supported amine sorbent was selected based upon superior performance to adsorb a greater amount of CO 2 than the activated carbon sorbents tested. When the most ideal sorbent at the time was selected, it was characterized and used to create a preliminary techno-economic analysis (TEA). A preliminary 550 MW coal-fired power plant using Illinois #6 bituminous coal was designed with a solid sorbent CO 2 capture system using the selected supported amine sorbent to both facilitate the TEA and to create the necessary framework to scale down the design to a 1 MWe equivalent slipstream pilot facility. The preliminary techno-economic analysis showed promising results and potential for improved performance for CO 2 capture compared to conventional MEA systems. As a result, a 1 MWe equivalent solid sorbent system was designed, constructed, and then installed at a coal-fired power plant in Alabama. The pilot was designed to capture 90% of the CO 2 from the incoming flue gas at 1 MWe net electrical generating equivalent. Testing was not possible at the design conditions due to changes in sorbent handling characteristics at post-regenerator temperatures that were not properly incorporated into the pilot design. Thus, severe pluggage occurred at nominally 60% of the design sorbent circulation rate with heated sorbent, although no handling issues were noted when the system was operated prior to bringing the regenerator to operating temperature. Testing within the constraints of the pilot plant resulted in 90% capture of the incoming CO 2 at a flow rate equivalent of 0.2 to 0.25 MWe net electrical generating equivalent. The reduction in equivalent flow rate at 90% capture was primarily the result of sorbent circulation limitations at operating temperatures combined with pre-loading of the sorbent with CO 2 prior to entering the adsorber. Specifically, CO 2 -rich gas was utilized to convey sorbent from the regenerator to the adsorber. This gas was nominally 45°C below the regenerator temperature during testing. ADA’s post-combustion capture system with modifications to overcome pilot constraints, in conjunction with incorporating a sorbent with CO 2 working capacity of 15 g CO 2 /100 g sorbent and a contact time of 10 to 15 minutes or less with flue gas could provide significant cost and performance benefits when compared to an MEA system.

36 MATERIALS SCIENCE↗
DOE OSTI2015

Bench-scale Development of an Advanced Solid Sorbent-based CO 2 Capture Process for Coal-fired Power Plants

It is increasingly clear that CO 2 capture and sequestration (CCS) must play a critical role in curbing worldwide CO 2 emissions to the atmosphere. Development of these technologies to cost-effectively remove CO 2 from coal-fired power plants is very important to mitigating the impact these power plants have within the world’s power generation portfolio. Currently, conventional CO 2 capture technologies, such as aqueous-monoethanolamine based solvent systems, are prohibitively expensive and if implemented could result in a 75 to 100% increase in the cost of electricity for consumers worldwide. Solid sorbent CO 2 capture processes – such as RTI’s Advanced Solid Sorbent CO 2 , Capture Process – are promising alternatives to conventional, liquid solvents. Supported amine sorbents – of the nature RTI has developed – are particularly attractive due to their high CO 2 loadings, low heat capacities, reduced corrosivity/volatility and the potential to reduce the regeneration energy needed to carry out CO 2 capture. Previous work in this area has failed to adequately address various technology challenges such as sorbent stability and regenerability, sorbent scale-up, improved physical strength and attrition-resistance, proper heat management and temperature control, proper solids handling and circulation control, as well as the proper coupling of process engineering advancements that are tailored for a promising sorbent technology. The remaining challenges for these sorbent processes have provided the framework for the project team’s research and development and target for advancing the technology beyond lab- and bench-scale testing. Under a cooperative agreement with the US Department of Energy, and part of NETL’s CO 2 Capture Program, RTI has led an effort to address and mitigate the challenges associated with solid sorbent CO 2 capture. The overall objective of this project was to mitigate the technical and economic risks associated with the scale-up of solid sorbent-based CO 2 capture processes, enabling subsequent larger pilot demonstrations and ultimately commercial deployment. An integrated development approach has been a key focus of this project in which process development, sorbent development, and economic analyses have informed each of the other development processes. Development efforts have focused on improving the performance stability of sorbent candidates, refining process engineering and design, and evaluating the viability of the technology through detailed economic analyses. Sorbent advancements have led to a next generation, commercially-viable CO 2 capture sorbent exhibiting performance stability in various gas environments and a physically strong fluidizable form. The team has reduced sorbent production costs and optimized the production process and scale-up of PEI-impregnated, fluidizable sorbents. Refinement of the process engineering and design, as well as the construction and operation of a bench-scale research unit has demonstrated promising CO 2 capture performance under simulated coal-fired flue gas conditions. Parametric testing has shown how CO 2 capture performance is impacted by changing process variables, such as Adsorber temperature, Regenerator temperature, superficial flue gas velocity, solids circulation rate, CO 2 partial pressure in the Regenerator, and many others. Long-term testing has generated data for the project team to set the process conditions needed to operate a solids-based system for optimal performance, with continuous 90% CO 2 capture, and no operational interruptions. Data collected from all phases of testing has been used to develop a detailed techno-economic assessment of RTI’s technology. These detailed analyses show that RTI’s technology has significant economic advantages over current amine scrubbing and potential to achieve the DOE’s Carbon Capture Program’s goal of >90% CO 2 capture rate at a cost of < $40/T-CO 2 captured by 2025. Through this integrated technology development approach, the project team has advanced RTI’s CO 2 capture technology to TRL-4 (nearly TRL-5, with the missing variable being testing on actual, coal-fired flue gas), according to the DOE/FE definitions for Technology Readiness Levels. At a broader level, this project has advanced the whole of the solid sorbent CO 2 capture field, with advancements in process engineering and design, technical risk mitigation, sorbent scale-up optimization, and an understanding of the commercial viability and applicability of solid sorbent CO 2 capture technologies for the U.S. existing fleet of coal-fired power plants.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2016

Nanoconfinement Effects in Catalysis

In this investigation, the unique properties that stem from the constrained environment and enforced proximity of functional groups at the active site were demonstrated for a number of systems. The first system is a nanocage structure with silicon-based, atom-thick shells and molecular-size cavities. The shell imparts the expected size exclusion for access to the interior cavity, and the confined space together with the hydrophobic shell strongly influences the stability of charged groups. One consequence is that the interior amine groups in a siloxane nanocage exhibit a shift in their protonation ability that is equivalent to about 4 pH units. In another nanocage structure designed to possess a core-shell structure in which the core periphery is decorated with carboxylic acid groups and the shell interior is populated with silanol groups, the restricted motion of the core results in limiting the stoichiometry of reaction between carboxylic acid and a Co 2 CO 8 complex, which leads to formation and stabilization of Co(I) ions in the nanocage. The second designed catalytic structure is a supported, isolated, Lewis acid Sn-oxide unit derived from a (POSS)-Sn-(POSS) molecular complex (POSS = incompletely condensed silsesquioxane). The Sn center in the (POSS)-Sn-(POSS) complex is present in a tetrahedral coordination, as confirmed by single crystal x-ray crystallography and Sn NMR, and its Lewis acid character is demonstrated with its binding to amines. The retention of the tetrahedral coordination of Sn after heterogenization and mild oxidative treatment is confirmed by characterization using EXAFS, NMR, UV-vis, and DRIFT, and its Lewis acid character is confirmed by stoichiometric binding with pyridine. This Sn-catalyst is active in hydride transfer reactions as a typical solid Lewis acid. In addition, the Sn centers can also create Brønsted acidity with alcohol by binding the alcohol strongly as alkoxide and transferring the hydroxyl H to the neighboring Sn-O-Si bond. The resulting acidic silanol is active in epoxide ring opening and acetalization reactions. The open structure of the Sn center makes it accessible to larger molecules, including cellobiose which can be converted to 5-(hydroxymethyl)-furfural. The third structure is a support planted with functional group pairing of a known separation distance. Using a precursor molecule that contains a hydrolysable silyl ester bond, and making use of known chemistry to convert silanol groups into amino/pyridyl and phosphinyl groups, silica surfaces with carboxylic acid/silanol, carboxylic acid/amine, carboxylic acid/pyridine, and carboxylic acid/phosphine pairs can be constructed. The amino groups paired with carboxylic acid on such a surface is more active in the Henry reaction of 4-nitobenzaldehyde with nitromethane.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2016

Optimizing the Costs of Solid Sorbent-Based CO 2 Capture Process Through Heat Integration

The focus of this project was the ADAsorb™ CO 2 Capture Process, a temperature-swing adsorption process that incorporates a three-stage fluidized bed as the adsorber and a single-stage fluidized bed as the regenerator. ADAsorb™ system was designed, fabricated, and tested under DOE award DEFE0004343. Two amine-based sorbents were evaluated in conjunction with the ADAsorb™ process: “BN”, an ion-exchange resin; and “OJ”, a metal organic framework (MOF) sorbent. Two cross heat exchanger designs were evaluated for use between the adsorber and regenerator: moving bed and fluidized bed. The fluidized bed approach was rejected fairly early in the project because the additional electrical load to power blowers or fans to overcome the pressure drop required for fluidization was estimated to be nominally three times the electrical power that could be generated from the steam saved through the use of the cross heat exchanger. The Energy Research Center at Lehigh University built and utilized a process model of the ADAsorb™ capture process and integrated this model into an existing model of a supercritical PC power plant. The Lehigh models verified that, for the ADAsorb™ system, the largest contributor to parasitic power was lost electrical generation, which was primarily electric power which the host plant could not generate due to the extraction of low pressure (LP) steam for sorbent heating, followed by power for the CO 2 compressor and the blower or fan power required to fluidize the adsorber and regenerator. Sorbent characteristics such as the impacts of moisture uptake, optimized adsorption and regeneration temperature, and sensitivity to changes in pressure were also included in the modeling study. Results indicate that sorbents which adsorb more than 1-2% moisture by weight are unlikely to be cost competitive unless they have an extremely high CO 2 working capacity that well exceeds 15% by weight. Modeling also revealed that reductions in adsorber pressure drop could negatively affect the CO 2 adsorption characteristics for sorbents with certain isobar adsorption characteristics like sorbent BN. Thus, reductions in pressure drop do not provide the efficiency benefits expected. A techno-economic assessment conducted during the project revealed that without heat integration, the a metal organic framework (MOF) sorbent used in conjunction with the ADAsorb™ process provided the opportunity for improved performance over the benchmark MEA process. While the addition of a cross heat exchanger and heat integration was found to significantly improve net unit heat rate, the additional equipment costs required to realize these improvements almost always outweighed the improvement in performance. The exception to this was for a supported amine sorbent and the addition of a moving bed cross heat exchanger alone or in conjunction with waste heat from the compressor used for supplemental regenerator heating. Perhaps one of the most important points to be drawn from the work conducted during this project is the significant influence of sorbent characteristics alone on the projected COE and LCOE associated with the ADAsorb™ process, and the implications associated with future improvements to solid sorbent CO 2 capture. The results from this project suggest that solid sorbent CO 2 capture will continue to see performance gains and lower system costs as further sorbent improvements are realized.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗
DOE OSTI2017

Layer-by-layer deposition of ultra-thin hybrid/microporous membrane for CO 2 separation

Based on two issued US patent, US7947579B2 and US8187678B2 that were invented by our team member at the University of New Mexico and Sandia National Labs, using atomic layer deposition technique (ALD) and molecular self-assembly or templating technique, An ultra-thin CO 2 membrane with CO 2 permeance up to 1580 GPU and CO 2 /N 2 up to 62 has been achieved in phase I project, promising for cost-effective CO 2 separations. As the first step of the project, a robust membrane fabrication protocol was established. To address the defects in the membrane structure, ALD treatment on AO support, multiple dip-coating processes and slow calcination steps were adopted. Consequently, defects were no longer evident in the nanoporous support, which ensures a reliable procedure for lab-scale membrane fabrications as well as the high-fidelity experimental findings. The same procedures may also be helpful for future scaling-up protocols. The layer-by-layer membrane fabrication was started by using a bridged disilane BTEE as the ALD precursor, wherein the organic groups at the bridging site were expected to be aligned layer-by-layer to form Angstrom-channels for CO 2 transport. Using 2-level factorial experimental design, we have found that ALD reaction time and ALD temperature were important factors impacting the CO 2 permeance and selectivity. Longer reaction time and higher ALD temperature were found to be advantageous for better CO 2 permeance and selectivity, which is in agreement with our model that better-aligned CO 2 -channels formed by the layer-by-layer stacking of the organic ligands can be achieved by a slower “stacking” process (longer reaction time) and stronger self-alignment tendency (higher ALD temperature). This observation will be an important guidance for our future membrane designs. The CO 2 -channel templated by –(CH 2 ) 2 - in BTEE was found to be too tight to facilitate fast CO 2 transport, but larger channel diameter is in contradiction with higher CO 2 selectivity. Therefore, the size-exclusion mechanism by itself is not sufficient for effective CO 2 separation. For this reason, the chemistry of the CO 2 -channel has to be carefully tuned. An amine bridged-disilane BTMA was therefore used as ALD precursor for larger CO 2 channel and high CO 2 -affinity chemistry. For BMTA membrane with amine chemistry measured at 100C, the CO 2 permeance was 1030 GPU for 100-cycle-ALD sample with CO 2 /N 2 selectivity of 17, and 302 GPU for 200-cycle-ALD sample with CO 2 /N 2 selectivity of 44. The increase of CO 2 permeance and the CO 2 /N 2 selectivity at elevated temperature is an evidence showing that there is a preferential chemical interaction between CO 2 and –NH functional groups in the membrane, which facilitates selective transport of CO 2 through the membrane. Therefore, using larger organic ligands as the CO 2 -channel template and the introduction of –NH chemistry to the membrane structure were proved to be an effective strategy in achieving better CO 2 permeance and selectivity. Guided by the same strategy, BTMA membrane was irradiated with UV to remove the bridging ligands for larger CO-channel, followed by Zn 2+ and Ni 2+ chemistry modification. Results showed that Zn 2+ or Ni 2+ chemistries will both enhance the selective CO 2 transport thereby the CO 2 /N 2 selectivity, and increasing separation temperature will further improve the CO2 permeance and selectivity. For BTMA membrane with Ni 2+ chemistry measured at 100C, CO 2 permeance of 1580 GPU and CO 2 /N 2 of 62 were achieved, promising for scaled-up industrial applications. Further, same membrane was tested at simulated flue gas condition (with SO 2 at 60C), the CO 2 permeance was 920 GPU and the CO 2 /N 2 selectivity was 52, suggesting the membrane still worked well under simulated flue gas conditions, primarily due to the stable ceramic framework of this membrane.

36 MATERIALS SCIENCE↗
DOE OSTI2017

An Advanced Catalytic Solvent for Lower Cost Post-Combustion CO 2 Capture in a Coal-Fired Power Plant

In this report, CAER addresses DOE’s objectives for improvements on post-combustion CO 2 capture through a three-fold approach including 1) advanced solvent, 2) homogeneous catalyst and 3) membrane carbon enrichment system. CAER-B3 solvent was formulated to improve the overall thermodynamics with the addition of a proton receiver while maintaining faster kinetics with the addition of thermally robust primary amine. The EH&S study indicates that CAER-B3 solvent poses little human toxicological or ecological risk in its raw material form. Generation of significant quantities of nitrosamines was deemed unlikely when using B3 solvent for CO 2 capture from coal-derived flue gas. The catalytic solvent caused a 21% reduction in energy demand, achievable via decreasing the liquid flowrate. Cyclic capacity nearly doubled due to the slower flowrate, and therefore, reduced the sensible heat required to remove CO 2 in the stripper. The increased rich loadings achieved by either pre-concentrating membrane or dewatering membrane prior to stripper, in addition to improved cyclic capacity, will lower downstream compression costs, while reducing the energy consumption per unit of CO 2 produced. Moreover, the CAER-B3 solvent demonstrated a greater thermal stability, lessening the rate of amine loss, caused by solvent degradation and emissions, by 50-70%. The CAER developed catalysts with a second order rate constant of 7.5 x 10 4 – 10 5 M -1 s -1 , far beyond those reported to date. The catalyst was designed to be a mimic of the enzyme carbonic anhydrase and increase the rate of CO 2 hydration to produce bicarbonate. As such, a 10-25% improvement in absorption rate was observed over the MEA base case. Enhancements can be imparted to the full scale system to reduce packing height of the absorber column, resulting in significant capital cost savings. Furthermore, the family of CAER catalysts showed less than 10% decomposition over 100 hours at 100 °C, suggesting that these catalysts will be stable in the harsh oxidative and thermal process conditions of an industrial carbon capture unit. Flue gas contaminants, such as NO x and SO x , also did not impact catalytic activity. A method for synthetic production of 500 g/batch was designed, verified, and well-documented, with scaling capabilities up to 500 kg. Two types of membranes were designed and tested for the purpose of increasing the solvent carbon loading prior to entering the stripper column. 500 hour and 100 hour verification studies were completed for the pre-concentrating membrane and zeolite dewatering membrane, respectively. Results demonstrated that a membrane-based CO 2 enrichment step using a commercial CO 2 membrane, or a zeolite dewatering membrane, or both, should be implemented in the carbon capture process to increase the CO 2 partial pressure by 16%, resulting in a stripping energy reduction of 35% relative to DOE Case 12 MEA solvent. Experimental data showed a carbon loading enrichment of 18-40% in comparison to the configuration without the pre-concentrating gas membrane. During the timespan of this project, challenges were identified and addressed so that enhanced performance may be realized long-term. Mitigation implementations included re-configuration of the bench unit with a solvent recovery column and a knock-out drum, as well as an increase in stripper pressure set point. Both changes resulted in a considerable reduction in the rate of solvent loss. Additionally, the membrane synthesis procedure was modified and validated to address zeolite dissolution concerns along with a new separation module. The techno-economic analysis conducted by WorleyParsons indicated the CAER-adCCS hybrid approach may outperform NETL Case 12 with regards to net plant HHV efficiency and cost of electricity.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2018

Nebraska Integrated Carbon Capture and Storage Pre-Feasibility Study

In collaboration with the Nebraska Public Power District (NPPD), the Energy & Environmental Research Center (EERC) has conducted a pre-feasibility study for a commercial-scale carbon dioxide (CO 2 ) geologic storage complex in western Nebraska integrated with potential CO 2 capture at Gerald Gentleman Station (GGS). GGS is the largest coal-fired electricity-generating station in Nebraska, emitting 8.5 million metric tons (Mt) of CO 2 annually, and is located near the town of Sutherland. This pre-feasibility (Phase 1) project has been executed as part of the U.S. Department of Energy (DOE) CarbonSAFE program, a multiphase initiative to support the deployment of large-scale carbon capture and storage (CCS) projects. Each CarbonSAFE project is required to demonstrate the potential to capture and store at least 50 million tonnes (Mt) of CO 2 over a 25-year operational period. The EERC and NPPD established a coordination team to identify challenges to a potential Nebraska CCS project, comprising local stakeholder organizations, which met twice in Lincoln and via several Webinars, providing feedback and guidance throughout the pre-feasibility study. The EERC also secured the technical support of Schlumberger Carbon Services and Computer Modelling Group Ltd. (CMG). The project comprised four technical themes, all using published information sources. Regional and stakeholder analysis, including identification of sensitive environmental areas, potential resource conflicts, and strategies for public outreach. A review of geographic and socioeconomic characteristics, in combination with geologic characterization in the subbasinal analysis described below, identified an area to the southwest and within a 75-mile radius of GGS as the most prospective for development of a storage site. This area largely avoided lands with protected status such as wetlands. A public outreach plan has also been developed for implementation in any further phases of CCS assessment in western Nebraska, for example a CarbonSAFE Phase 2 feasibility study. Scenario analysis, addressing economic and regulatory factors. GGS is the only single major source of CO 2 emissions capable of satisfying the CarbonSAFE 50-Mt scale requirement within the study region. Chemical absorption using amines was identified as the most viable technology for postcombustion CO 2 capture at GGS. The total cost of a CCS project at GGS was estimated to be between $67/tonne CO 2 for capture and auxiliary boiler to minimize parasitic load and $70/tonne CO 2 avoided cost, using the Carnegie-Mellon University Integrated Environmental Control Model (IECM). The total avoided cost included the capture facility and parasitic load, a flue gas desulfurization plant required for the use of amine solvent technology, transport via pipeline, and dedicated storage infrastructure. Nebraska has no legislation in place to address typical CCS-specific issues, for example pore space ownership for storage. Long-term liability, therefore, falls under the U.S. Environmental Protection Agency Underground Injection Control (UIC) Class 6 program regulations. Subbasinal analysis, addressing the potential for a dedicated subsurface “container” to store the required 50-Mt quantity of CO 2 . Modeling and simulation studies identified an area to the southwest of GGS with the potential for storage of 50 Mt CO 2 in the Cloverly Formation, comprising sandstones with interbedded and intermingled shales. The area of review (AOR) that would be required for monitoring under a Class VI operating permit was estimated to be as high as 400–700 square miles, due to uncertain pressure effects. The viability of this storage option is subject to significant uncertainty due to the relatively limited amount of existing characterization data available to the pre-feasibility study; for example, dynamic simulation indicated that the proposed storage rate might require as little as two or as many as 14 injection wells. A key uncertainty is the relative proportion and distribution of sandstone and shale within the Cloverly Formation. A preliminary, semiquantitative risk assessment also suggested uncertainty over storage capacity and injectivity constitute the most significant project risks at this pre-feasibility stage. No assessed risks were considered to rule out the possibility of a project moving to deployment. National Risk Assessment Partnership (NRAP) validation, using software tools developed by the National Energy Technology Laboratory (NETL) to assess risks associated with the potential 50-Mt CO 2 storage complex. NRAP tools were used to assess hypothetical leakage scenarios. Results broadly supported the conclusion of the semiquantitative risk analysis – for example, even worst-case analysis of theoretical leakage scenarios found limited migration rates and impacts. In summary, the work undertaken in this Phase 1 pre-feasibility study has shown that western Nebraska has potential to host a commercial-scale CCS project, including a dedicated storage “container” for 50 Mt of CO 2 . However, the following key challenges would need to be overcome: The business case for deploying CCS projects is uncertain; recently announced federal tax credits and sales of CO 2 for enhanced oil recovery may not cover the full costs of a CCS project at GGS, as estimated by this pre-feasibility study. The potential 50-Mt CO 2 dedicated storage container defined in this pre-feasibility study should be regarded as having a relatively low level of readiness to support a CCS project. Public outreach would be a vital element in western Nebraska, where sensitivities around such environmental issues as water resource protection and pipeline construction would need to be carefully addressed.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2018

Lab-Scale Development of a Solid Sorbent for CO 2 Capture Process for Coal-Fired Power Plants

It is increasingly clear that CO 2 capture and sequestration (CCS) must play a critical role in curbing worldwide CO 2 emissions to the atmosphere. Development of these technologies to cost-effectively remove CO 2 from coal-fired power plants is very important to mitigating the impact these power plants have within the world’s power generation portfolio. Currently, conventional CO 2 capture technologies, such as aqueous-monoethanolamine based solvent systems, are prohibitively expensive and if implemented could result in a 75 to 100% increase in the cost of electricity for consumers worldwide. Solid sorbent CO 2 capture processes – such as RTI’s 3rd Generation Solid Sorbent CO 2 Capture Process – are promising alternatives to conventional, liquid solvents. Supported amine sorbents – of the nature RTI has developed – are particularly attractive due to their potential for high CO 2 loadings, excellent stability over multiple cycles, reduced corrosivity/volatility and a potential to reduce the regeneration energy needed to carry out CO 2 capture. The remaining challenges for these sorbent processes have provided the framework for the project team’s research and development and target for advancing the technology beyond lab-scale testing. Previous work in this area has failed to adequately address various technology challenges such as sorbent stability and regenerability, sorbent scale-up, improved physical strength and attrition-resistance, proper heat management and temperature control, proper solids handling, as well as the proper coupling of process engineering advancements that are tailored for a promising sorbent technology. Under a cooperative agreement with the US Department of Energy, and part of NETL’s CO 2 Capture Program, RTI has led an effort to address and mitigate the challenges associated with solid sorbent CO 2 capture. The overall objective of this project was to mitigate the technical and economic risks associated with the performance and scale-up of solid sorbent-based CO 2 capture processes, enabling subsequent larger pilot demonstrations and ultimately commercial deployment. An integrated development approach has been a key focus of this project in which sorbent development, process development, and economic analyses have informed each of the other development processes. Development efforts have focused on developing novel hybrid solids-based CO 2 capture sorbents and improving their performance stability, refining process engineering and design, and evaluating the viability of the technology through detailed economic analyses. Sorbent advancements have led to a next generation, commercially-viable CO 2 capture sorbent exhibiting performance stability in various gas environments and a physically strong fluidizable form. The team has reduced sorbent production costs and optimized the production and scale-up of novel metal-organic framework (MOF) hybrid solids-based CO 2 capture sorbents, fluidizable sorbents. Refinement of the process engineering and design at the lab-scale research unit has demonstrated promising CO 2 capture performance in simulated coal-fired flue gas conditions. Long-term testing has informed the project team on the process conditions needed to operate a solids-based system for optimal performance. Data collected from all phases of testing has been used to develop a detailed techno-economic assessment of RTI’s technology. These detailed analyses show that RTI’s technology has significant economic advantages over current amine scrubbing and potential to achieve the DOE’s Carbon Capture Program’s goal of >90% CO 2 capture rate at a cost of almost $40/tonne CO 2 captured by 2025. Through this integrated technology development approach, the project team has advanced RTI’s 3rd generation CO 2 capture technology to TRL-3, according to the DOE/FE definitions for Technology Readiness Levels. At a broader level, this project has advanced the whole of the solid sorbent CO 2 capture field, with advancements in process engineering and design, technical risk mitigation, sorbent scale-up optimization, and an understanding of the commercial viability and applicability of solid sorbent CO 2 capture technologies for the U.S. existing fleet of coal-fired power plants.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2011

Eliminating the Derate of Carbon Capture Retrofits

Retrofitting existing PC plants with amine-based CO 2 capture technology is thermally- and power-intensive. This study examines the benefit of installing a natural gas simple cycle to provide the auxiliaries required to operate the amine system such that the original power demand can still be met.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2019

Combined Sorbent/WGS-based CO 2 Capture Process with Integrated Heat Management for IGCC Systems

Southern Research has developed a combined CO 2 capture water-gas shift (WGS) process for integrated gasification combined cycle (IGCC) applications. A highly efficient regenerable magnesium based sorbent was prepared to remove CO 2 . It offers high and stable CO 2 capacity with minimum requirement for temperature and pressure swings. Under optimized conditions, the sorbents achieved up to 8 mmol/g of CO 2 working capacity and remained stable over 500 cycles of adsorption and regeneration. The selected WGS process achieved 96% CO per pass conversion and remained isothermal during the test duration that lasted over 500 cycles. The approach showed potential to reduce cost of electricity (COE) compared to the baseline carbon capture approaches. The process is for bench-scale and pilot development. In a commercial embodiment, syngas from the gasifier is cooled to warm gas conditions. It then enters the CO 2 sorbent-shift reactor that uses an efficient MgO-based CO 2 sorbent and a commercial catalyst to shift the CO to CO 2 and capture 90% + of the carbon. Using a dual-bed arrangement, the sorbent is regenerated periodically by a combination of pressure and temperature swing to maintain steady state conditions and produce a 95+ % CO 2 stream for sequestration. The hydrogen rich syngas is sent to the IGCC for power production. In addition to consolidating CO 2 capture with WGS, the proposed process reduces parasitic energy losses by operating at warm gas temperatures and reduces parasitic plant load (i.e., steam and auxiliary power) by reducing energy required for regeneration. The project consisted of 3 budget periods (BP) of laboratory-scale research and testing with go/no-go decisions after BP-1 and BP-2. In the 12 month BP-1, it was shown show that one promising sorbent maintained the required CO 2 capacity and durability of >1.5 mmol/g over 100 cycles. Also based on sorbent and WGS experiments in separate reactors and combined reactor modeling, it was shown that the process had the potential to capture 90% of the CO 2 at a lower than conventional amine-based approach. In the 18 month BP-2, a lab scale combined sorbent/WGS reactor system was built, commissioned, and tested with the promising sorbent from BP-1. 90% carbon capture was demonstrated over 100 cycles and it was shown that the process continued to have potential to capture 90% of the carbon at a cost that was less than the conventional amine-based approach. In the 6 month BP-3, a long term test was conducted using the best SR sorbent. The required durability of > 2 mmol/g was demonstrated after 500 cycles. Also, 90% carbon capture and 96% CO conversion was maintained over 1000 cycles. A technical and economic feasibility study was carried out to compare the proposed pre-combustion approach to a gasification plant employing a conventional pre-combustion approach and a conventional pulverized caol (PC) plant employing a conventional post combustion CO 2 capture approach.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2019

Post Combustion Carbon Capture using Polyethylenimine (PEI) functionalized Titanate Nanotubes

In order to overcome the drawbacks of solvent amines such as, MEA and DEA, scientists and engineers are looking for some great alternatives for CO 2 capture. Different PEIs have widely been investigated to functionalize different solid support materials used for CO 2 capture in recent 15 years. This report provides an overview of the recent advances of such PEI-functionalized adsorbents, in which PEI are loaded on different silica materials, nanotubes, membranes and other materials such as, mesoporous alumina, clay, activated carbon, fly ash, mesoporous carbon, mesoporous sponge-like TUD-1, metal organic frameworks, nanofibrillated cellulose, porous chitosan bead, resin, glass fiber, zeolites, etc. Among them, PEI-funtionalized PTNTs using titanate nano tubes is selected, and various PEIfunctionalized PTNTs were fabricated for CO 2 capture from the flue gas in fossil energy power generation. To investigate the effects of synthesis conditions on the CO 2 capture capacities, two different temperatures (130 and 140°C) and three times (1, 3 and 5 days) were used in the hydrothermal process. Material characterization with TEM and XRD confirmed that PTNTs were successfully synthesized in all the cases, and PEI was loaded onto the PTNTs with the wet impregnation process. The nano-tubular size, porosity and surface areas of the PTNTs varied with the synthesis conditions, and the PTNTs synthesized at 130°C possess the bigger pore size than those synthesized at 140°C. The CO 2 capture experiment using simulated flue gas under wet condition showed that overall highest capture capacity of 78-79 mg g-1 was achieved with the adsorbents synthesized at 130°C and with the synthesis time of 3 or 5 days. Besides, the CFD simulation model is developed by using MFIX for the PEI-PTNTs solid sorbents suggested in our carbon capture experiments. For this, the simulation model is calibrated through adjusting the concentration of active amines sites based on the comparison between simulation and experiment. After that, the simulation model of the adjusted titan-based solid sorbent is used for checking the performance of the solid sorbents and finding the optimized flow rate in the reactor model developed by NETL.

36 MATERIALS SCIENCE↗
DOE OSTI2022

Universal Solvent Viscosity Reduction via Hydrogen Bonding Disruptors

Liquid Ion Solutions LLC (DBA RoCo Global) in partnership with Carnegie Mellon University and Carbon Capture Scientific LLC, has performed lab-scale development and evaluation of novel additives that lower the viscosity of water-lean amine solvents for post-combustion carbon dioxide capture. This project focuses on developing additives that minimize the formation of long-range electrostatic and hydrogen bonding (HB) networks, decreasing the solvent viscosity, improving diffusion, and improving the process economics. The project objectives included: 1) performing computer simulation to understand the molecular interactions of the additive molecules in water-lean CO 2 capture solvents, 2) design and synthesis of HB disruptors additives, 3) performance testing with additive molecules on model amine solvents, and 4) demonstration of the effectiveness of the optimized additives in the presence of synthetic flue gas. To meet the abovementioned objectives, the project team utilized a holistic approach that combines molecular simulation, experimental testing, and economic analysis studies. The project team developed ab initio molecular model and then perform computer simulation to develop relationship between hydrogen bonding, viscosity, and performed quantitative analysis of additive on the viscosity of the solvent. The team completed computational comparative study on a range of organic functional groups such as ethers, esters, cyclic carbonates, alkanes, and ammonium salts for their effect on viscosity gaining key insights into molecular interactions and the impact of various functional groups and molecular shapes on viscosity. Assisted with molecular simulation insights, the project team conducted additive synthesis and testing, including a proof-of-concept study, additive screening, optimization, and synthetic flue gas testing. The experimental proof-of-concept study proved that the hydrogen bonding acceptors result in significant decrease of viscosities. Detailed additive screening (exploring various functionalities and molecular structures) has been performed. Several promising additives showed excellent reduction in viscosity (30-41%) at 5% additive loading, and over 50% viscosity reduction at 10% additive loading for the model solvents. The team also performed complex screening studies on additive loadings and mixing effect among additives using the design of experiments. Based on multiple screening experiments, one additive-solvent candidate was down-selected for synthetic flue gas testing. A 100-hour continuous absorption/desorption study was conducted under simulated flue gas using a lab-scale continuous capture and separation system. No degradation (for both solvent and additive) was observed based on the GC results of the solvent samples collected from the continuous study. The team conducted preliminary engineering analyses and cost-benefit analyses to quantify the potential economic benefits of the additive approach for solvent viscosity reduction. Based on the experimental data, CO 2 capture cost savings from the capital and operating cost savings are estimated at $\$$4.7/tonne and $\$$0.3/tonne CO 2 captured, respectively. Considering the additive cost, the net benefit is estimated to be between $\$$4.32~$\$$4.86/tonne CO 2 captured.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2024

Multi-pronged approach to improving carbon utilization by cyanobacterial cultures

The goal of this project was to increase the efficiency of carbon utilization by a Synechocystis biofuel production strain in a photobioreactor system by at least 50% using a multi-pronged approach that combined the best features of both biological and physicochemical CO 2 capture technologies to: 1) increase rates and extent of CO 2 absorption into the culture medium by addition of biocompatible amine solvents and a nanobubble gas delivery system, and 2) increase cellular rates of inorganic carbon uptake and carbon fixation through genetic engineering. In addition, the project plan included evaluating the use of fermentation effluent gases as a CO 2 source and demonstrating performance under outdoor conditions in closed-pond photobioreactor systems. These combined efforts would be guided by integrated technoeconomic and life-cycle analyses. Both physicochemical CO 2 capture technologies explored proved to be successful. The amine solvent monoethanolamine (MEA) was found to be biocompatible with a Synechocystis laurate production strain. Using an adaptive evolution strategy, an MEA-tolerant laurate production strain was developed that showed significantly increased carbon utilization over the parent strain. To our knowledge this was the first time nanobubble (NB) technology had been used as a carbon delivery system for algae production and it also proved quite successful as a proof of concept. Solutions containing CO 2 nanobubbles (Nano-BG11) at concentrations significantly higher than the aqueous CO 2 concentrations achieved with gas sparging were successfully generated and characterized with regard to bubble size (nm), concentration (NB/L), and pH stability as per project plan. Growth studies proved challenging. However, once the source of a puzzling growth defect was found and remedied Synechocystis was able to grow somewhat better in Nano-BG11 than in standard BG11 medium.

09 BIOMASS FUELS↗
DOE OSTI2022

High-Temperature Ceramic-Carbonate Dual-Phase Membrane Reactor for Pre-combustion Carbon Dioxide Capture (Final Scientific/Technical Report)

Arizona State University, in collaboration with University of South Carolina, worked on a project aimed at development of a new high temperature, high pressure CO 2 perm-selective membrane reactor for water-gas-shift reaction (WGS) with simulated gasifier syngas to produce a high concentration H 2 stream with CO 2 capture. The membrane reactor is made of a CO 2 semi-permeable ceramic-carbonate dual-phase (CCDP) membrane with high CO 2 perm-selectivity/permeance and thermal/mechanical stability for application in WGS reaction. The objectives of this project were to (1) synthesize the chemically/thermally stable tubular CCDP membranes with CO 2 permeance and selectivity (with respect to H 2 , CO or H 2 O) larger than 6.5×10-7 mol/m2·s·Pa and 500, respectively; (2) establish CCDP membrane reactor setup and study high pressure CO 2 permeation and WGS reaction with CO 2 capture using the setup; and (3) identify conditions for WGS in the CCDP membrane reactor that produce CO 2 and H 2 streams with purity of >99% and >90% respectively at CO conversion >95% and overall carbon capture >90%. The work in this project included both membrane development and membrane reactor process study. The membrane development efforts were focused on investigating a H 2 S resistant and highly oxygen-ionic conducting metal oxide material and membrane for CO 2 separation, fabrication of tubular samaria-doped-ceria/molten-carbonate CCDP membrane with high mechanical strength, and experimental and modeling study of high-pressure CO 2 permeation of the CCDP membranes. Mathematical models were developed to describe WGS in the CCDP membrane reactor without a catalyst or packed with a commercial high temperature WGS catalyst. Experiments on WGS in the CCDP membrane reactor with the commercial WGS catalyst, guided by the model analysis, were performed to identify optimum conditions for achieving the CO conversion, carbon capture, and the purity of the H 2 and CO 2 streams mentioned above. At 30 atm feed pressure, 750°C operation temperature, space velocity of 250 h-1, and with steam sweep, a single-stage CCDP membrane reactor with average CO 2 permeation flux of 0.5 cm3(STP)/min.cm2 can achieve CO 2 conversion of 95% and overall carbon capture of 94%, and produce CO 2 and H 2 streams with dry-based purity of >99% and 92% respectively. The project also included process design and techno-economic analysis (TEA) for a CCDP membrane reactor process for WGS reaction with CO 2 capture for a 550 MW coal-fired IGCC power plant, and its comparison with the conventional fixed-bed reactor system for WGS with follow-up CO 2 capture by an amine absorption process. The target performance for the reactor for WGS with CO 2 capture includes CO conversion >95%, hydrogen stream purity >90%, CO 2 stream purity >95%, and total carbon capture >90%. The CCDP membrane developed in this project can achieve the performance target, without subsequent CO 2 capture process at the optimum conditions identified in this project. The outcome of the process design and TEA analysis shows that the membrane reactor for WGS with in-situ CO 2 capture has an operating cost about 40% lower than that for the conventional fixed-bed reactor with a separate amine absorption process for CO 2 capture. However, the capital cost of the membrane reactor process is about twice that of the conventional process because of the higher cost of the CCDP membrane. Modeling analysis shows that a membrane reactor using a CCDP membrane with higher CO 2 permeance (about three times the current value) can deliver the targeted performance for WGS reaction with CO 2 capture at a much higher space velocity and lower membrane surface area to catalyst volume ratio, leading to a smaller catalyst amount and/or membrane area and hence significantly reduced membrane reactor capital costs.

20 FOSSIL-FUELED POWER PLANTS↗